Hydraulically operated well packer apparatus



May 24, 1966 K. LEUTWYLER 3,252,516

HYDRAULICALLY OPERATED WELL PACKER APPARATUS 9 Sheets-Sheet 1 Filed Nov.5, 1962 INVENTOR. K027 LEurn fl 2 flrroeusYs.

May 24, 1966 K. LEUTWYLER 3,252,516

HYDRAULICALLY OPERATED WELL PACKER APPARATUS 9 Sheets-Sheet 2 Filed NOV.5, 1962 M60 3Q: FI Go 3 0 60 36' 1 0.

INVENTOR.

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May 24, 1966 K. LEUTWYLER 3,252,516

HYDRAULICALLY OPERATED WELL PACKER APPARATUS Filed Nov. 5, 1962 9Sheets-Sheet 3 E0 4 56 Fiat 50 INVENTOR.

K097 LEUTWYL EQ May 24, 1966 K. LEUTWYLER HYDRAULICALLY OPERATED WELLPACKER APPARATUS Filed Nov. 5, 1962 9 Sheets-Sheet 4 INVENTOR.

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May 24, 1966 K. LEUTWYLER 3,252,516

HYDRAULICALLY OPERATED WELL PACKER APPARATUS 9 Sheets-Sheet 5 Filed Nov.5, 1962 INVENTOR. Ever Laura/meg flrraezvsys.

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HYDRAULICALLY OPERATED WELL PACKER APPARATUS 9 Sheets-Sheet 7 Filed NOV.5, 1962 INVENTOR. K1187 LEUTWyLEIZ y 1966 K. LEUTWYLER 3,252,516

HYDRAULICALLY OPERATED WELL PACKER APPARATUS Filed Nov. 5, 1962 9Sheets-Sheet 8 a2 8IG. I: 6U 67 I at? i\ M 11$ 85 as 4 a4 1% ass F T WE88 35 {I 87 89 i i 90 5 INVENTOR. E027 LEurwyL 52 14 rraRA/EYS.

United States Patent 0 M Filed Nov. 5, 1962, Ser. No. 235,258 25 Claims.Cl. 166-120) The present invention relates to subsurface well boreequipment, and more particularly to well packer apparatus adapted to tobe set in well bores.

Some packers are set hydraulically in well bores and may be maintainedin set condition by the continuous application of hydraulic pressurethereto. If the pressure in the well bore applied to a packer isrelieved or diminishes below a minimum setting value, release of thepacker from the wall of the wellbore occurs. The trapping of hydraulicpressure in the well packer can make its continued set conditionindependent of subsequent pressure in the well bore, but such trappedpressure diminishes or becomes a nullity in the event of subsequentpartial extrusion or cold flow of the packing material (forming thesealing portion of the packer against the wall of the well bore) andaround adjacent well packer parts, resulting in undesired release of thepacker from the well bore wall.

Accordingly, it is an object of the present invention to provide a wellpacker set by fluid or hydraulic pressure, in which ample fluid pressureis constantly available in the packer to maintain it in packed-oilcondition in the well bore despite diminution of the pressure in thewell bore below the minimum packer setting pressure, and despitesubsequent partial extrusion or cold flow of the packing material of thewell packer.

Another object of the invention is to provide a well packer adapted tobe set in the well bore by fluid pressure, in which the fluid pressurecan be trapped or confined in the packer to insure its maintenance inset condition despite an excessive diminution of the well bore pressure,and in which the pressure can be easily relieved in the event it isdesired to release the packer from the wall of the well bore.

A further object of the invention is to provide a well packer set in awell bore by hydraulic or fluid pressure applied to a fluid operatedactuator portion of the packer and maintained in set condition bytrapping fluid pressure therewithin, which the packer is releasable fromthe wall of the well bore by substantially simultaneously communicatingthe high and low pressure sides of the fluid operated actuator toessentially the same pressure source in the well bore, as, for example,simultaneously bleeding or venting the high and low pressure sides ofthe actuator.

An additional object of the invention is to provide a well packer havingan improved mechanism for preventing premature setting of the packerwhile it is being run in the well bore.

Yet a further object of the invention is to provide a well packeradapted to be set in a well bore by fluid pressure, in which release ofthe well packer is efifected by equalizing the pressure across its fluidpressure operated actuator, and in which inadvertent or prematurepressure equalizing is prevented.

Another object of the invention is to provide a well packer adapted tobe set in the well bore by fluid pressure, in which the packer iscapable of adjustment for setting under one pressure condition or underanother condition. The packer may be adjusted for setting when atripping device is moved through it, or it may be adjusted or convertedso that the tripping device merely conditions it for subsequent setting.

3,252,516 Patented May 24, 1966 Yet another object of the invention isto provide well packers capable'of being run in tandem in a well boreand set therein, the order of setting of the packers being preselectedso that one can be set in advance of another, or some or all can be setsimultaneously.

Still a further object of the invention is to provide a subsurface welltool having parts initially secured together by a frangible device, inwhich torque required to shear the frangible device is much greater thanthe corresponding longitudinal force required to shear the same device.

Another object of the invention is to provide a subsurface well toolhaving parts releasably connected together, as by means of a frangibleconnection, in which the parts are released from one another, or thefrangible connection disrupted, by the application of a much lesserforce than the strength of the connection, such lesser force beingtransmitted-to the connection through a mechanical advantage or forcemultiplying device.

A further object of the invention is to provide a Well packer or packershaving parallel passages therethrough for communication with paralleltubular strings extending to the top of the well bore, which packer orpackers are capable of accomplishing the aforementioned objectives.

This invention possesses many other advantages, and has other objectswhich may be made more clearly apparent from a consideration of a formin which it may be embodied. This form is shown in the drawingsaccompanying and forming part of the present specification. It will nowbe described in detail, for the purpose of illustrating the generalprinciples of the invention; but it is to be understood that suchdetailed description is not to be taken in a limiting sense, since thescope of the invention is best defined by the appended claims.

Referring to the drawings:

FIGURE 1 is a side elevational view of a well packer embodying theinvention, with its parts in retracted position;

FIGS. 2a and 2b together constitute a longitudinal section through thewell packer disclosed in FIG. 1, with the parts in their initialposition for lowering in a well casing, or similar conduit string,disposed in the well bore, FIG. 2b being a lower continuation of FIG.2a;

FIGS. 3a, 3b, 3c and 3d together constitute a side elevational view,with parts broken away, of a tandem packer arrangement disposed in awell bore for conducting production from a plurality of zones throughparallel tubular strings to the top of the well bore, FIGS. 3b, 3c and3d being lower continuations of FIGS. 3a, 3b and 3c, respectively;

FIG. 4 is an enlarged longitudinal section through the hydraulicactuator portion of the well packer with its parts in their initialconditon;

FIG. 5 is an enlarged cross-section taken along the line 55 on FIG. 4;

FIG. 6 is an enlarged cross-section taken along the line 6-6 on FIG. 4;

FIG. 7 is an enlarged cross-section taken along the line 77 on FIG. 4;

FIG. 8 is an enlarged longitudinal section through a hydraulic controlunit embodied in the well packer, adjusted for. one operating condition;

FIG. 9 is a view similar to FIG. 8 disclosing the control unit adjustedor disposed in another operating condition;

FIG. 10 is a view of the lower portion of FIG. 9 illustrating its checkvalve in an open condition;

FIGS. lla and 11b are longitudinal sections, on an enlarged scale, ofthe apparatus illustrated in FIGS. 2a and 2b, showing the well packeranchored in packed-off condition in the well casing, FIG. llb being alower continuation of FIG. 11a;

FIGS. 12a and 12b are enlarged fragmentary, longitudinal sectionsillustrating the hydraulic actuator in its position after havingeffected expansion of well packer parts outwardly against the wellcasing, FIG. 12b being a lower continuation of FIG. 12a;

FIGS. 13a, 13b and 130 are enlarged longitudinal sections, with partsshown in :side elevation, of one side of the parallel packer with theparts shifted to a packer releasing condition, FIGS. 13b and 130 beinglower continuations of FIGS. 13a and 1312, respectively;

FIG. 14 is a fragmentary cross-section, on an enlarged scale, of part ofthe apparatus illustrated in FIG. 6, disclosing a bleeder portion of theapparatus;

FIG. 15 is a view similar to FIG. 14 showing the apparatus in conditionfor bleeding pressure from the cylinder mechanism of the packerapparatus;

FIG. 16 is an enlarged cross-section taken along the line 1616 on FIG.1;

FIG. 17 is an enlarged fragmentary longitudinal section taken along theline 17-17 on FIG. 2b;

FIG. 18 is a cross-section taken along the line 1818 on FIG. 13c;

FIG. 19 is a longitudinal section, with parts broken away, of a forcemultiplier embodied in the apparatus in its initial position;

FIG. 19a is a view similar to FIG. 19 of the force multiplier in anotheroperating condition;

FIG. 20 is an enlarged cross-section taken along the line 29-20 on FIG.1;

FIGS. 21 and 22 together constitute an elevational view and longitudinalsection of the tubular portions interconnecting the upper and lowerpackers, FIG. 22 being a lower continuation of FIG. 21; and

FIG. 23 is a View of the ported portion of the apparatus shown in FIG.21 in another operative position.

A well packer A or B is illustrated in the drawings which can be loweredwithin and set in a well casing C for the purpose of conducting wellproduction from a plurality of separate producing zones D, E, F in thewell bore through separate paths and separate parallel tubular stringsG, H to the top of the well bore. A plurality of well packers A, B(FIGS. 3a, 3b, 30) may be run in the well bore in tandem relation andset hydraulically therewithin, being placed in appropriate relation to athird packer I which may have been previously set in the well bore orwell casing.

, As shown, the well packer I may have been previously anchored inpackedotf condition in the well casing above lower casing perforations10 communicating with the lower producing zone D in the well bore. Anintermediate packer B is to be disposed in the well casing above a setof intermediate casing perforations 11 communicating with theintermediate producing zone E, and an upper well packer A is to be setin the well casing C above upper casing perforations 12 communicatingwith the upper producing zone F. The upper packer A is placed incommunication with a pair of parallel tubular strings G, H extending tothe top of the well bore. Production from the intermediate and lowerzones E, F may be conducted selectively to the top of the well bore.

The upper and intermediate packers A, B are structurally the same. Priorto being run in the well bore, they may be conditioned or adjusted forsetting hydraulically at different times. Thus, the intermediate wellpacker B may be adjusted to be set hydraulically without effectinghydraulic setting of the upper packer A, the latter packer beinghydraulically set at any desiredtime thereafter, which time interval maybe a matter of minutes.

As disclosed, each well packer A, B includes first and second paralleltubular body members 13, 14, the second body member 14 having an upperthreaded pin 15 threaded in a lower bore 16 in a receptacle or parallelstring head 17. In connection with the upper packer A, a first tubularstring G is connected to the first body member 13 which extends slidablythrough the receptacle 17,

a second tubular string H extending to the top of the well bore andcommunicating with a second passage 18 extending through the parallelstring head. The second tubular string H can be lowered from the top ofthe well bore into the casing C for reception within the second passage18. As shown (FIG. 11a), the lower portion of the second tubular stringincludes a sub 19 having a suit able side seal 20 mounted thereon forsealing against the Wall of the second passage 18. Depending from thissub is a latch device, including a plurality of spring-like arms 21having central cam projections or fingers 22 adapted to be receivedunder a flange or shoulder 23 in the parallel string head 17 below thesealing region of the second passage. These fingers are engageable withthe head shoulder 23 when the second tubular string H is being insertedin the passage 18, such engagement springing the fingers 22 and arms 21inwardly sufficiently so that the fingers ride past the shoulder 23 to aposition therebelow for the purpose of releasably retaining the secondtubular string H in the second passage with its seal engaging the wallof the latter. The exertion of a sufficient upward pull on the secondtubular string causes the fingers 22 to engage the lower tapered surface24 of the head shoulder, which cams or forces the fingers and the latcharms 21 inwardly until the fingers ride past the flange 23, therebyreleasing the second tubular string H from the head 17 and permittingits complete withdrawal from the second passage 18, and, if desired,enabling it to be removed entirely from the well casing C and the wellbore.

In the use of the well packer apparatus, it may be lowered in the wellcasing on the first tubular string G to the desired setting location, ifonly one packer is involved, or to appropriately locate the tandemintermediate and upper packers A, B in the well casing. Thereafter, thesecond tubular string H is lowered in the well casing, and will engagean inclined head or guide surface 25 at the top of the receptacle 17,which will guide or steer the lower portion of the second tubular stringtoward and into the second passage 18.

The first tubular string G is suitably connected, as by means of acoupling 26, to the first tubular body member 13 of the upper packer Awhich extends slidably through a first longitudinal passage 27 in thereceptacle or head 17. The first tubular body member extends completelythrough the packer and has a suitable lower connection 28 for attachmentto the devices therebelow, as, for example, to first tubing 29 which mayextend downwardly therefrom for appropriate association or connectionwith the packer B therebelow, and, more particularly for connection tothe first tubular body member 13 of the intermediate packer B.

The first and second tubular body members 13, 14 of a packer A or Bextend through an upper connector 30 engaging the lower end of theparallel string head 17, this upper connector being secured to thesecond tubular body or mandrel 14 by a two-piece ring 31 located in aperipheral groove 32 in the second tubular body member and receivedwithin a counterbore 33 in the upper connector, and also contacting anupper insert 34 through which the body members extend. The insert 34 isclamped to the lower end of the upper connector 30, and also against thetwo-piece coupling ring 31 of the second tubular body member 14, by anuppergauge ring 35 threaded on the upper connector 30 and having aninwardly directed flange 36 engaging the upper insert. The upper insert34 also is adapted to contact a two-piece stop ring 37 mounted in aperipheral groove 38 in the first tubular body member 13, the ring beingreceived within an enlarged diameter bore 39 through the upper connector30 which communicates with a counterbore 40 extending upwardly in thereceptacle 17 from its lower end, and whichterminates in a downwardlyfacing shoulder 41. The first tubular body member 13 may be moved by thefirst tubular string G upwardly of the connector 30 and the receptacle17, its stop ring 37 sliding in the connector bore 39 and in thecounterbore 40 until it engages the downwardly facing receptacleshoulder 41.

The first and second tubular body members 13, 14 extend downwardlythrough and into an initially and normally retracted packing structure42, an expander 43, a slip structure 44 for anchoring the well packeragainst longitudinal movement in the well casing, and a hydraulicactuating mechanism 45. The packing structure 42 can assume any desiredform. As shown, it includes a plurality of pliant, elastic packingelements 46, made of rubber or rubber-like material, and interveningspacers 47, through which the body members 13, 14 extend. The upperpacking element 46 engages the upper gauge ring 35 and insert 34, itslower end engaging a spacer 47, which, in turn, engages an intermediatepacking element 46 contacting a spacer 47 that engages a lower packingelement 46 which contacts a lower insert 48 slidably receiving the bodymembers. The lower packing element also contacts a lower gauge ring 49having an inwardly directed flange 50 clamping the lower insert 48against the upper end of the expander 43.

The expander 43 is provided with a pair of bores 51 through which thefirst and second body members 13, 14 slidably extend. The expander 43,lower insert 48 and lower gauge ring 49 are movable as a unit relativeto the first and second tubular body members 13, 14. Downward movementof these parts relative to the second tubular body member 14 isprevented by a two-piece stop ring 52 mounted in a peripheral groove 53in the second body member 14 and engaging the lower end of the lowerinsert 48. The bore 51 through the expander 43 below the insert 48 is ofan enlar ed diameter along an extended length to permit relativedownward movement of the second body member 14. As a precautionarymeasure, such relative downward movement is limited by engagement of.the stop ring 52 with the lower end 54 of the expander defining the endof its enlarged diameter bore.

The lower expander 43 has a plurality of spaced slots 54a, the bases 55of which provide expander surfaces tapering in a downward and inwarddirection. The upper portions of slips 56 are disposed in these slots,the inner portions of the slips having tapered surfaces 57 companion tothe expander surfaces 55 and movable longitudinally relative thereto, aswell as laterally outwardly and inwardly into and from engagement withthe wall of the surrounding well casing C. Each slip 56 has opposed sidetongues 58 slidably in companion grooves 59 in the expander 43, so thatthe slips are moved positively from an expanded to a retracted positionupon longitudinal separating movement between the expander 43 and slips56, and are also capable of being held positively in a retractedposition. The lower ends of the slips are connected to a slip ring 60having a pair of bores 61 through which the body members 13, 14 extend,there being a slidable connection between lower T-shaped heads 62 of theslips and companion T-shaped grooves 63 formed in the slip ring. SuchT-shaped connections 62, 63 causes the slips 56 to move jointlylongitudinally with the slip ring 60 while permitting their movementradially of the slip ring toward the well casing and from the wellcasing. To facilitate such radial movement, the T-shaped heads 62 andthe companion grooves 63 in the slip ring are inclined to a small extentin an outward and downward direction.

The first and second tubular body-members 13, 14 extend downwardly fromthe slip ring through a thrust sleeve structure 64 and into the firstand second parallel passages 65, 66 of a hydraulic housing 67 forming aportion of the hydraulic actuating mechanism 45. The thrust sleeve 64interconnects the hydraulic housing 67 with the slip ring 60. As shown,the thrust sleeve is formed in two halves and has an upper internalflange 68 received within a peripheral groove 69 in the slip ring 60.Similarly, the thrust sleeve 64 has a lower internal flange 70 receivedwithin a peripheral groove 71 in the upper portion of the hydraulichousing 67. The upper flange 68 is prevented from removal from the slipring groove 69 by a retainer ring 72 encompassing the slip ring 60 andan upwardly extending skirt 73 on the thrust sleeve. Upward longitudinalmovement of the retainer ring 72 from the skirt 73 is prevented byengagement of the ring 72 with the slip ring 60. The slip ring hascircumferentially spaced recesses 74 therein and the retainer ring hascompanion teeth 75 thereon. When the teeth 75 are disaligned with therecesses 74, the ring 72 encompasses the thrust sleeve skirt 73, beingheld in such disaligned position by screws 76 disposed on opposite sidesof one of the teeth 75. When disassembly of the thrust sleeve is tooccur, the screws 76 are removed and the ring 72 turned to place itsteeth 75 in alignment with the slip ring recesses 74, the retainer rin72 then being shiftable upwardly from an encompassing relation to theskirt 73, in view of the ability of its teeth 75 to enter the slip ringrecesses 74.

In a similar manner, the lower flange is prevented from being removedfrom its groove 71 by a retainer ring 72 encompassing the hydraulichousing 67, and also a lower skirt 73 of the thrust sleeve, the lowerretainer ring 72 being held in appropriate assembled relation in thesame manner as the upper retainer ring, having circumferentially spacedteeth adapted to move into circumferentially spaced recesses 74 in thehydraulic housing 67, which are substantially the same as the recesses74 in the slipring 60. Screws 76 disposed on opposite sides of a lowerring tooth 75 and threaded into the housing 67 will prevent turning ofthe lower ring 72 into a position aligned with the housing recesses 74.

The first tubular body member 13 is releasably connected to the lowerportion of the hydraulic housing 67, and, for that matter, also to theslip ring 69 so that it cannot move longitudinally with respect toeither of these parts when the well packer is being lowered in the wellcasing. The releasable connection between the first body member 13 andthe hydraulic housing 67 includes a shearable device. An upper face cam80 is mounted in a counterbore 81 in the lower portion of the housing 67and is fixed to the housing by a screw 81a or the like, its upper endbearing against a housing shoulder 82. This face cam 80 engages acompanion driving face cam or sleeve 83 surrounding the body member 13and rotatable therewith by securing keys 84 to the cam sleeve receivedwithin keyways or grooves 85 in the body member. The lower end of thedriving cam 83 engages the outer portion of a shear ring 86, the innerportion of which extends within a peripheral groove 87 in the mandrel13. This shear ring may be made of two halves and is held inwardly inthe groove 87 by a retainer ring 38 which encompasses the shear ring 86and which has a recess 89 therebelow to permit the outer portion of theshear ring to move downwardly thereinto along the mandrel 13 after ithas been sheared or detached from the inner portion of the shear ring.The driving cam sleeve 83 can also shift downwardly into the recess 89in the retainer ring. The re tainer ring 88 is held in its upperposition surrounding the shear ring 86 by a guide ring 90 threaded onthe housing 67 and through which the first body member 13 extends, aswell as a tubular sub 91 threadedly secured to the lower end of thehydraulic housing in alignment with the second body member 14.

The first body member 13 is prevented from moving downwardly relative tothe hydraulic housing 67 and the slip ring 60 connected thereto by astop ring 92 which is in the form of a C ring adjustably threaded on themandrel 13 and engaging an upper shoulder 93 on the hydraulic housing.Engagement of the adjustable st-op ring 92 with the housing 67 preventsany downward force from being transmitted from the tubular body tothe'shear ring 86, which might prematurely disrupt the ring 86. Upwardmovement of the mandrel 13 is prevented by the shear ring 86 engagingthe lower end of the cam sleeve 83, which, in turn, engages the face cam80 fixed to the housing, and which also engages the housing shoulder 82.

The driving cam 83 is initially prevented from being turned by themandrel 13 by one or more shear screws 94 threaded into the housing 67and into the driving cam. The application of sufficient torque on thefirst body member or mandrel 13' can disrupt this screw 94, allowing thedriving cam 83 to turn and causing the coengaging inclined cam faces 95to force the sleeve 83 downwardly against the shear ring 86, disruptingthe latter, and thereby freeing the mandrel 13 for upward movementwithin the hydraulic housing 67, and, for that matter, as explainedhereinbelow, for upward movement to release the well packer from thewell casing after it has been set there'within.

Thefirst body member 13 and also the second body member 14 arereleasably locked to the slip ring 60 to prevent their longitudinalmovement with respect to this latter part. Since the upper end 15 of thesecond body member 14 is attached to the receptacle 17, its securing ofthe slip ring 60 prevents the receptacle from moving toward the slipring, which is essential for outward expansion of the slips 56 andpacking elements 46 against the well casing C. The releasable locking ofthe first body member 13 to the slip ring 60 will prevent any upwardthrust of the tubular mandrel 13 from being transmitted to the shearring 86, and thereby inadvertently shear or disrupt the latter.

The lock devices for initially securing each body member 13, 14 to theslip ring 60 include a lock sleeve 96 surrounding each body member, withits upper portion cirwith a plurality of circumferentially spacedlongitudinal slots forming legs 98 terminating in inwardly directedfingers 99 received within a circumferential groove 100 in itsassociated body member 13 or 14. The fingers of both sleeves 96 areinitially held in their grooves 100 by an encompassing connector plate101 through which each body member slidably extends. It is necessary toshift the connector plate 101 downwardly free from the fingers 99 todisconnect the body members 13, 14 from the slip ring 60 and permittheir longitudinal movement with respect thereto.

Initially, the connector plate 101 is held in its upward position byshear screws 102, 103, 104 attaching it to the first body member 13. Asshown, an upper shear screw 102 secures the connector plate 101 to thebody member 13 and two longitudinally spaced shear screws 103, 104 areconnected to the plate and are disposed within an elongate slot orgroove 105 in the first body member 13 (see FIG. 17). With the shearscrew, frangible arrangement disclosed, all three screws are eifectivefor resisting rotation of the first body member 13 relative to theconnector plate 101. However, only one of the screws is effective at anytime for preventing longitudinal movement.

of the connector plate 101 relative to the first body member or mandrel13. Assuming a downward force to be imposed on the connector plate 101,such downward force is at first transmitted only through the uppermostshear screw 102 to the first body member 13, since this screw makes asnug fit in a socket 106 in the body member, and the other two screws103, 104 are spaced from the lower end of the elongate groove 105 andalso from one another. Accordingly, the imposition of sufiicientdownward force on the connector plate 101 will first shear the upperscrew 102, the plate then moving downwardly until the lower screw 104engages the lower end of the groove 105. The imposition of sufficientforce to overcome the shear value of the lower screw 104 will result inits disruption and a further downward movement of the connector plate101 along the body member 13, until the intermediate screw 103 engagesthe broken inner portion of the lower screw, which is in contact withthe lower end of the groove. The imposition of sufficient downward forceon the connector plate to overcome the shear strength of theintermediate screw 103 will then result in its disruption and the fullfreeing of the connector plate from the first body total of 18,000pounds would be available for resisting turning or torque of the firstbody member; whereas, only 6,000 pounds, the shear strength of a singlescrew, re-

sists downward movement of the connector plate 101 along the first bodymember 13.

The force for setting the well packer is transmitted through theconnector plate 101, as described hereinbelow, to the second body member14. As shown, the second body member has a thrust ring 107 thereonspaced initially below the upper shoulder 108 of a counterbore 109 inthe connector plate. The connect-or plate can move downwardly along bothbody members 13, 14, following disruption of the shear screws 102, 103,104, until the connector plate shoulder 10% engages the second body ring107, at which time the connector plate 101 will have been removed fromthe latch fingers 99 of both latch sleeves 96, which will then allow theconnector plate to shift the second body member 14 downwardly within theslip ring 60. In view of the shearing of the screws 102, 103, 104initially securing the connector plate to the first body member, suchdownward movement will not tend to move the first body member 13downwardly, which will remain in its fixed position, in view of itsthrust ring 92 engaging the shoulder 93. Its upward movement isprevented by the lower shear ring mechanism -88.

Downward movement of the second body 14 with respect to the slip ring 60results in outward expansion of the slips 56 and shortening and outwardexpansion of the packing structure 42 into engagement with the wall ofthe Well casing C. Such downward movement and setting of the normallyretracted parts of the well packer are effected hydraulically, and morespecifically by the hydrostatic head of fluid in the well bore or wellcasing. The hydraulic housing 67 is provided with a plurality ofcylinders 110 closed at their lower ends, each cylinder containing apiston structure that includes a piston 111 suitably secured to a pistonrod 112 extending upwardly from the piston and through an accumulatorand cylinder head structure 113. Such accumulator structure includes amovable cylinder head 114, through which the rod extends, slidable alongthe wall of the cylinder and having seal rings 115, 116 slidably sealingagainst the cylinder wall and the piston rod. A stop ring and springthrust member 117 surround the piston rod 112 and is threadedly securedto the movable cylinder head 1 14, extending upwardly within a springhousing 118 that extends downwardly within the cylinder 1 10 with itsupper end lthreadedly secured to the hydraulic housing 67. A pluralityof Belleville washers or conical spring members 119 are disposed withinthe housing 1 18 around the rod 112, the lower end of the conical springassembly engaging the spring thrust member 117, and its upper endengaging a spring seat 120 surrounding the piston rod 112 andthre'adedly secured within the spring housing 118. Leakage around thespring housing 118 is prevented by one or more seal rings 1-21 thereonengaging the wall of the cylinder 110; whereas, leakage of fluid alongthe piston rod 112 is prevented by one or more seal rings 122 mounted inthe spring seat 120 and slidably and sealingly engaging the piston rod.

The springs 119 exert a constant force on the stop ring and thrustmember 117 to shift it downwardly to the extent limited by engagement ofthe stop ring 117 with a housing shoulder 123. The exertion ofsufficient hydraulic force in the cylinder 1 on the movable cylinderhead 1 14 can shift the latter upwardly and store energy or spring forcein the springs 1*19, tor the purpose described hereinbelow.

Each cylinder communicates with an inlet port 124 above its piston 11dand immediately below its movable cylinder head 114, communicatingthrough a check valve 125, and also through a balanced piston valve 126,with the second passage 66 through the hydraulic housing 67, into whichthe second body member 14 extends. Each cylinder also communicates withpressure equalizing or vent ports 127, 128 communicating throughbreakable plug devices i129, 130 with the first passage 65 through thehydraulic housing 67, these vent ports opening into a cylinderimmediately below its head 114, and also into the lower end of thecylinder below the piston.

Each piston has a suitable seal ring structure 131 thereon slidably andsealingly engaging the wall of the cylinder and held on the piston by asuitable retainer ring 132. Initially, the cylinder space 133 belowthepiston contains air at atmospheric pressure, the vent ports 127, 128leading from a cylinder on opposite sides of its piston each beingclosed by a transverse breakable closure plug 134 extending across avent port with side ports 135 communicating therewith that open into acentral passage 136, the inner end of which is closed by an end wall 167of the plug extending into the first housing passage 65 and into asocket 138 in the first body member 13. The breakable plug 134 is heldin position by a closure plug 139 threaded into a housing bore 140.Leakage of fluid from the bore containing the breakable plug and closureplug is prevented by side seal rings 141 mounted thereon and engagingthe wall of the bore. The break-able plug 134 is also prevented fromlongitudinal shifting by a set screw 142 threaded in the housing andextending into a peripheral groove 143 in the breakable plug. The outerportion 144 of the central passage 136 through the breakable pl-ug maybe threaded to facilitate removal of the plug from its bore, after theclosure plug 139 has been removed, by threading a suitable tool or rod(not shown) thereinto, which will then enable the break-able plug 134 tobe pulled out of the housing bore 140.

The cylinders 110 above the pistons 111 are in fluid communication witheach other through a transverse passage 145 extending therebetween, andthe lower portions of the cylinders below the pistons are incommunication with each other through an interconnecting pass-age 146provided in the hydraulic housing. Accordingly, the introduction offluid pressure into one cylinder above its piston will result in thesame fluid pressure passing through the interconnecting passage 145 tothe other cylinder above the piston. Similarly, the venting of onecylinder above the piston will also result in the venting of the othercylinder. The placing of one cylinder below its piston in communicationwith the first passage 65 through the housing 67 will also result in thecorresponding placing of the other cylinder in communication with suchpassage because of the interconnecting passage 146.

The cylinder space 133 below each piston 111 contains air initially atatmospheric pressure, such cylinder space being closed by the breakableplug device 130 to prevent any fluid pressure from entering the lowerend of one cylinder, as well as the lower end of the other cylinder.Fluid under pressure from the second housing passage 66 is initiallyprevented from entering an inlet port 150 opening into the balancedpiston valve structure 126, and communicating through the check valve125 with the inlet port 124 to a cylinder 110. The first-mentioned inletport 150 opens into the second passage 66 through the hydraulic housing,which is closed initially by a sleeve valve 151 in the second passagesecured to the lower end of the second body member 14 by shear screws152. The valve sleeve carries suitable spaced side seal rings 153sealingly engaging with the wall of the second housing passage onopposite sides of the inlet port 150. The valve sleeve hascircumferentially spaced longitudinal slots in its lower portionproviding spring-like legs 154 terminating in fingers 155 which projectinwardly of the sleeve to an eitective internal diameter less than theinternal diameter through the second body member 14, and also throughthe upper imperforate portion of the valve sleeve 151. When a suitabletripping ball valve element 156 is lowered or pumped through the secondtubular string H, it passes through the second body member 14 and comesto rest upon the fingers 155. Thereafter, fluid pressure can be built upof a suflicient value to overcome the shear strength of the screws 152,shifting the sleeve valve 151 downwardly in the housing passage 66 to aposition opening the inlet port 150 and allowing fluid pressure to flowtherethrough and into the balanced piston valve structure 126 (describedhereinbelow). When the balanced piston valve structure is opened, suchfluid can then flow through the check valve 125 and through the ports124, 145 communicating with the cylinders above the pistons 111, for thepurpose of shifting the pistons in a downward direction. The valvesleeve 151 is shifted downwardly hydraulically to a position in whichits fingers 155 are aligned with a circumferential housing recess 157,the fingers expanding outwardly into such recess to increase theirinternal diameter and allow the ball 156 to pass downwardly therethroughand out of the well packer into the well casing C, or downwardly out ofan upper well packer A and into a lower well packer B, assuming a tandemarrangement of well packers is being run in the well casing for settingtherewithin.

When the hydrostatic head of fluid in the well casing can act downwardlyon the pistons 111, they move downwardly pulling the rods 112 downwardlywith them. Thrust nuts 158 threaded on the piston rods 112 and receivedwithin counterbores 159 in the connector plate 101 transmit the downwardmovement of the rods to the connector plate 101. Initially, theconnector plate 101 is held in an upward position by the shear screws102, 103,

104 attaching them to the first body member 13. When in this condition,the upper end 160 of each piston rod is disposed in an atmosphericchamber 161 in the slip ring 60, fluid being prevented from passing intothis chamber by a suitable side seal ring 162 on the upper end of eachrod engaging the cylindrical wall of the atmospheric chamber 161. Inview of the sealing of the upper end of each rod in its associatedatmospheric chamber, the hydrostatic head of fluid cannot act initiallyon the upper end of the rod 112, tending to shift it downwardly.However, when the hydrostatic head of fluid acts on the pistons 111 toexert a sufficient force thereon and on the rods 112 to shear the screws102, 103, 104 and move the rods and connector plate 101 downwardly withrespect to the slip ring 60, the upper ends 160 of the rods are pulledout of the atmospheric chamber 161, allowing the hydrostatic head offluid to act in a downward direction over the entire cross-sectionalarea of the piston rods. In effect, the hydrostatic head of fluid canthen act in a downward direction over the entire cross-sectional area ofeach piston 111, bringing to a maximum the total hydraulic forceavailable for downward movement of the piston rods and connector plate.

Each well packer A, B has a control unit (FIGS. 8 to 10) incorporatedtherein which includes the balanced piston valve structure 126, so thatthe well packer can be preadjusted to allow the fluid pressure to passinto its cylinders for the purpose of setting the well packer upondownward shifting of the valve sleeve 151 within the second housingpassage 66, or to prevent setting of the packer as a result of suchdownward shifting of the sleeve valve, until an appropriate pressuredifferential has been imparted to the fluid in the second housingpassage 66. Moreover, it is desired to trap fluid pressure in eachcylinder 110 to hold the well packer in packed-off condition, despitethe fact that the hydrostatic head of fluid in the well casing maysubsequently diminsh considerably, as, for example, as might result frominstallation of gaslift equipment in the well casing.

As specifically disclosed, the control unit for the packer includes avalve body 165 extending downwardly into a longitudinal chamber 166 inthe hydraulic housing 67, the upper portion 166 of the valve body beingthreadedly secured to the housing. The valve body has a central passage167 therethrough and side ports 168 communicating with this centralpassage and with the inlet port 150 opening into the second housingpassage 66. Leakage of fluid around the valve body 165 is prevented bysuitable seal rings 169 mounted thereon and engaging the wall of thehousing chamber 166 on opposite sides of the ports 168. A piston valvestructure 170 is slidable longitudinally in the valve body 165,extending upwardly through a stop member and closure 171 threaded intothe upper end of the valve body. Sliding of the piston valve member 170may be facilitated by providing an enlarged guide portion 172 thereonslidable against the bore wall of the valve body 165.

The piston valve member 170 may be disposed in a position preventingcommunication between its ports 168 and a lower central passage 173through the piston. Thus, the piston structure includes a lower head 174slidable in a cylindrical valve seat 173 in the lower portion of thevalve body 165, and also an upper head 175 slidable in the cylindricalbore 167 of the valve body. The lower piston head 174 is of a muchsmaller diameter than the upper piston head 175, so that fluid pressurewithin the valve body between the piston-s can act over a larger area ofthe upper piston head and shift the entire piston structure 170 upwardlyto a position fully removing the lower piston head 174 from itscylindrical seat 173 and opening this central passage 173 tocommunication with the body ports 168. A suitable seal ring 176 ismounted on the lower head for sealing engagement against the cylindricalvalve seat 173, a seal ring 177 also being mounted on the upper head 175for sealing engagement with the wall of the cylindrical valve body bore167. Another seal ring 178 is mounted on the piston and slidably sealsagainst the cylindrical wall of the end body closure member 171.

The piston valve member 170 is balanced against hydraulic shifting underthe action of the hydrostatic head of fluid in the well bore. The valvebody 165 between the upper piston 175 and the seal ring 178 on the uppersteam portion 179 of the piston structure 170 initially contains air atatmospheric pressure. The hydrostatic head of fluid in the well bore isacting in a downward direction over the entire cross-sectional area T ofthe steam portion 170 of the piston valve. When the inlet port 150 isopen, the hydrostatic head of fluid is also acting in a downwarddirection over the annular area S of the lower piston head 174. Suchhydrostatic head of fluid is acting in an upward direction on the largerupper piston 175 over its annular area R. The piston valve parts are soproportioned that the area R equals the sum of the areas S and T.Accordingly, the hydrostatic head of fluid in the well bore is actingover equal and opposite areas on the piston valve structure 170 andcannot efiect shifting of such piston valve in an upward direction.

The control valve unit can be conditioned initially with its parts inthe position disclosed in FIG. 8, preventing communication between thevalve body port 168 and its central passage 173 below the lower pistonhead 174. The piston valve may be retained in this position by a shearscrew 180 threaded through the closure member 171, with its inner endextending within a peripheral groove 181 in the valve stem 179.Appropriate location of the groove 181 in alignment with the shear screw180 and limiting of downward movement of the piston valve member 170within the valve body housing 165 are obtained by engagement of a stopnut 182 threaded on the upper end of the stem 179 with the upper end ofthe enclosure member 17'1, inadvertent loosening of the nut 182 beingprevented by a lock nut 183 threaded on the stern and bearing againstthe stop nut.

Upon the provision of fluid under suflicient pressure within the valvebody between its upper and lower piston heads 175, 174, such pressurewill act in an upward direction on the greater area of the upper pistonhead to shear the screw 1'80 and shift the piston valve device upwardlyto remove the lower head 174 from its cylindrical seat and the centralpassage 173 in the valve body 165, the upward movement being limited byengagement of the guide 172 with the lower end of the closure memher171. The stem 179 of the piston valve member 170 carries a latch orcatch 184 in a slot 185, which is pivot ally mounted on a pin 186extending across the slot, the latch being initially confined within thestem 179 by the encompassing closure member 171 (FIG. 8). However, whenthe piston valve 170 is shifted to an upward position, the latch 1 84 isdisposed above the closure member 171, whereupon a spring 187 encirclingthe pivot pin 186, with one arm 188 bearing against the stem 179 at theupper end of the slot and the other arm 189 engaging the catch 184, willswing the catch 184 in a counterclockwise direction, as seen in FIGS. 8and 9, placing it above the closure member 171. Any tendency for thepiston valve member 170 to shift downwardly in the valve body is thenprecluded by engagement of the latch 184 with the closure member.

If desired, the control unit can first be adjusted so that the pistonvalve 126 is in the open position illustrated in FIG. 9. The shear screw180 need merely be omitted and the piston valve member 170 movedupwardly manually until its latch 184 is disposed above the closuremember 171, the latch then precluding downward movement of the pistonvalve to a position placing its lower piston head 174 within itscylindrical valve seat 173.

Assuming the piston valve device 126 to be open, fluid can now pass fromthe second passage 66 in the fluid actuator housing 67 and through theports 150, 168 into the central passage 167, 173. Such fluid, if under asufficient pressure, will open the check valve 125 and pass into theport 124 leading into one of the cylinders 110 above its actuatingpiston 111. As disclosed, the check valve 125 includes a valve housing190, the upper end of which is threadedly secured to the lower end ofthe valve body 165 of the piston valve 126. A valve stem 191 is slidablein the lower portion of the valve housing 190, having a valve head 192adapted to engage a rubber seat 193 suitably bonded to the exterior ofthe valve body 165. A helical compression spring 194 surrounds the valvestem 191, its lower end engaging a spring seat 195 provided by thehousing, and its upper end engaging the check valve head 192 to urge thehead against the elastic seat 193. When the fluid pressure above thevalve head 192 overcomes the force of the spring 194, the head isshifted downwardly from engagement with its companion seat 193, the headand valve stem 191 sliding downwardly within the housing until the head192 is disposed below the upper ends of a plurality of longitudinalslots a in the housing 190 which communicate with the port 124 leadingto a cylinder 110. If the pressure in the valve body passage 173decreases sufliciently, the spring 194 will shift the valve head backinto engagement with its seat 193, the pressure in the cylinder 110being prevented from bleeding therefrom.

The first body member 13 has longitudinally spaced sockets 138 receivingthe inner ends 137 of the breakable plugs 134. The body member 13 alsohas a plurality of longitudinal external grooves 196 thereon which willfacilitate bleeding of fluid from the cylinders 110, and also the entryof fluid thereinto, following actuation of the first body member 13 todisrupt or break the outer ends 137 of the plugs from the remainder ofthe plugs 134, in order to open their central passages 136. Plugbreaking will occur either as a result of turning of the first bodymember 13, or as a result of moving the first body member 13longitudinally within the hydraulic housing 67.

Assuming that only a single hydraulically actuated packer is to be runin and set in the well casing, its first body member 13 is secured tothe first tubular string G with the parts in the retracted positionillustrated in FIGS. 2a and 2b. If desired, the control unit may beplaced in the condition illustrated in FIG. 9, with the shear screw 18%omitted so that the central passage through the valve body 167, 173communicates with the body ports 168 and with the inlet port 150 leadinginto the second passage 66. The well packer is lowered by the firsttubular string G in the well casing C to the desired setting point,after which the second tubular string H is lowered in the well casingalongside the first tubular string, engaging the upper head and shiftingdownwardly into the second receptacle passage 18, becoming latchedthereto. If desired, connections to the first and second tubular stringsG, H can be made at the top of the well bore. It is unnecessary tothereafter longitudinally move any of the tubular strings. The well borecan now be conditioned by pumping circulating fluid down through thesecond tubular string H, such fluid passing through the second passage66 of the packer apparatus and discharging from the lower couplingmember 91 into the casing, forcing the drilling mud, or other undesiredfluids in'the casing, upwardly around the packer and around the tubularstrings G, H to the top of the well bore.

When it is desired to set the well packer, a tripping ball 156 is pumpeddown the second tubular string H, passing into the second body member 14and coming to rest upon the fingers 155 of the valve sleeve 151. Thebuilding up of pressure in the second tubular string to a sufiicientvalue will overcome the strength of the shear screws 152, disrupting thelatter and shifting the sleeve valve downwardly to a position openingthe inlet port 150, the sleeve valve 151 moving downwardly until itsfingers 155 expand into the housing recess 157, allowing the ball tomove down through the tubular connector or coupling 91 and completelyout of the packer, dropping into the well casing. The hydrostatic headof fluid in the well bore can now pass through the inlet port 150 andthrough the valve body ports 168 into the central passage 167, 173 ofthe latter, shifting the check valve member 192, 191 downwardly from itsseat 193, and moving through the inlet port 124 into a cylinder 110above a piston 111 and through the intercommunicating port or passage145 into the other cylinder 110 above its piston. The hydrostatic headof fluid is present in both cylinders, acting upwardly on the cylinderheads 114, moving them upwardly and storing energy in the conical springassemblies 119, which'may be collapsed to solid height.

The pistons 111 move downwardly in the cylinder 1111, shifting the rods112 downwardly with them and forcing the connector plate 101 downwardlyafter shearing the screws 1112, 103, 104 securing the connector plate tothefirst body member 13. The connector plate moves downwardly intoengagement with the second body member thrust ring 107 and completelyfrom encompassing relation to the latch fingers 99, allowing the latterto expand from-the body member grooves 100. The connector plate engagesthe second body member ring 107 and shifts the second body member 14downwardly within the slip ring 60, shifting the receptacle 17 connectedto the second body member, upper connector 31), upper insert 34, andupper gauge ring downwardly toward the slip ring 60. The slip ringcannot move downwardly at this time, since it is attached to the firstbody member 13 through the thrust sleeve 64, hydraulic housing 67, camsleeves 80, 33, and shear ring 86. Accordingly,

the receptacle 17, upper connector 33, upper insert 34, and upper gaugering 35 move downwardly, carrying the packing structure 42 and expander43 downwardly with them, effecting a shifting of the expander downwardlyalong the slips 56 and expanding the latter outwardly into engagementwith the wall of the well casing C, precluding further downward movementof the expander 43. Continued downward movement of the second bodymember 14 along the first body member 13 will then move the upperreceptacle 17, upper connector 31 upper insert 34, and upper gauge ring35 toward the expander, shortening the packing structure 42 andexpanding the packing elements 46 outwardly against the wall of the wellcasing C and firmly into sealing engagement will the tubular bodymembers 13, 14 extending therethrough. The well packer is now inpacked-off condition within the well casing (FIGS. 11a, 11b).

The hydrostatic head of fluid is normally sufiicient and available toenter the cylinders 110 through the check valve to act constantly uponthe pistons 111 and urge them downwardly in their cylinders 110,maintaining the slips 56 and packing structure 42 expanded against thewall of the well casing. If the hydrostatic head of fluid decreasesbelow the closing force of the check valve spring 154, the check valve125 closes and traps pressure in the cylinders 1111, such pressure beingconstantly exerted upon the pistons, urging them in a downward directionand maintaining the packing structure 42 and slips 56 firmly engagedagainst the wall of the well casing. If the packing elements 46 were toextrude around the companion spacer rings 47 and gauge rings 35, 49, sothat the pistons 111 would move downwardly to a further extent in thecylinders 11th, in the absence of sufficient hydrostatic head in thewell bore, the trapped pressure within the cylinders 11%) would bedissipated and the hydraulic force to maintain the packer anchored inpacked-off condition in the well casing would no longer be present.However, with the packer illustrated and described, the pressure passinginto the cylinders for the purpose of setting the packer has compressedthe conical springs 119 and has stored energy therewithin, such springstending to shift the movable cylinder heads 114 downwardly in thecylinders 110. Such springs constantly exert a force on the cylinderheads 114 to maintain pressure in the liquid within the cylinder 11d.Accordingly, if the pistons 111 were to move downwardly to a furtherextent within their cylinders, as a result of extrusion of packingmaterial, or the like, an action which would ordinarily diminish thepressure in the cylinders or reduce such pressure to zero, the cylinderheads 114 would shift downwardly under the action of the conical springwashers 119- and maintain the liquid under pressure. In other words, theforce of the springs 119 would then be transferred through the trappedliquid in the cylinders 11% to the pistons 111, urging them in adownward direction and thereby maintaining the slips 56 and packingstructure 42 expanded against the wall of the well casing. In effect,the springs 119 function as a pressure accumlator to insure the presenceof adequate pressure in the cylinders for holding the packer set in thewell casing, despite the loss of hydrostatic head of fluid in the wellcasing, and despite downward movement of the pistons in the cylinders toa further extent as a result of extrusion or cold flow of the rubber orrubber-like packing elements 46.

Ordinarily, the first tubular body member 13 will be connected throughan appropriate length of tubing to a packer therebelow, to conduct fluidfrom a lower production zone through the first tubular string G to thetop of the well bore. Production from an upper zone between the lowerpacker and the packer A will pass into and through the second passage 66through the packer and the second tubular string H to the top of thewell bore.

In the event it is desired to release the packer from the well casingand remove it therefrom, the pressure in the cylinders 110 on oppositesides of the pistons 111 is equalized. Since the pressure on the highpressure side of the pistons 111 may be trapped, by virtue of closing ofthe check valve 125, the cylinder regions on the high pressure side ofthe pistons, as well as the cylinder regions on the atmospheric or lowpressure side of the pistons, are open to the first passagesimultaneously. A straight-line pull can be taken on the first tubularstring G to pull upwardly on the first body member 13. If such pull issuflicient, it will disrupt the shear ring 86, as well as the inner ends137 of the break plugs 134, opening the passages 136 through the breakplugs and cstablishing communication therethrough between each cylinderon opposite sides of its piston 111 and the surrounding well bore, thecommunication being established through the clearance space between thefirst tubular body member 13 and the first passage 65 in the hydraulichousing, which space may be increased by virtue of the circumferentiallyspaced longitudinal grooves 196 in the exterior of the first bodymember. The fluid in the well bore can now pass into the cylinders 110below the pistons 111 and any excess fluid pressure will bleed from thecylinders above the pistons 111. The conical springs 119 can expand tothe extent determined by engagement of the stop rings 117 with the stopshoulders 123 on the housings 118.

Following equalizing of the pressure, the second tubular string H can beremoved from the receptacle 17, if

- such removal has not been previously accomplished, by

taking a sufiicient upward pull on the second tubular string H whichwill cause the latch fingers 22 to engage the shoulder 23, shifting thefingers inwardly until they ride past the shoulder, whereupon the secondtubular string H can be pulled completely out of the receptacle 17 andremoved from the well bore.

An upward pull can now be taken on the first tubular string G, whichwill move the first body 13 upwardly until its ring 37 engages thereceptacle shoulder 41. A continuation of the upward pull will move thereceptacle 17, second body or mandrel member 14, and the parts above thepacking 42 connected thereto, upwardly with respect to the expander 43,allowing the packing elements 46 to retract from the well casing. Thesecond body member 14 will move upwardly until its ring 52 engages thelower insert 48, whereupon its continued upward movement will shift theexpander upwardly relative to the slips 56, the slips being retractedfrom the well casing by virtue of the tongue and groove interconnections58, 59 with the expander 43. The well packer can now be elevated in thewell casing through elevation of the first tubular string G and removedentirely therefrom.

In lieu of disrupting the break plugs 134 and the shear ring 86 bytaking a direct upward pull on the first tubular string G and first bodymember 13, the break plugs and the shear ring can be disrupted byturning the first tubular string G and body member 13. The applicationof suflicient torque to the body member 13 will break the inner ends 137of the plugs from their main portion to open their central passages 136.Such turning movement will also be transmitted to the cam sleeve 83.Initial turning of the cam sleeve will shear the screws 94 that attachesit to the hydraulic housing 67, after which turning of the sleeve 83relative to the upper cam member will cause the latter to shift thesleeve 83 downwardly, exerting a sutficient force on the shear ring 86to shear its outer portion from its inner portion disposed within themandrel groove 87. Because of the angle of inclination of the cam facesof the coengaging cam members, a very great mechanical advantage isprovided, so that a force equivalent to the torque imparted to the firsttubular body member 13 is multiplied several times in exerting alongitudinal shearing force on the shear ring 86. A comparatively lowtorque can be converted to a very high shearing force on the ring 86 byuse of the force multiplier 83, St).

The slips 56 heretofore described anchor the packer in the well casingagainst downward movement. If desired, it can also be anchored againstupward n enent. The receptacle or head is provided with generallyrat'ially disposed cylinders 220, the inner portions of whichcommunicate with the second head passage 18 through intervening ports221. Each cylinder contains a gripping member 22?. having wickers orteeth 223 adapted to embed themselves in the wall of the well casing Cand resist upward movement. The gripping members are urged initiallytoward a retracted position completely within the cylinders 220 byhelical compression springs 224, engaging retainers and spring seats 225extending across vertical slots 226 in the gripping members and suitablysecured to the receptacle 17, and also engaging the gripping members 222themselves. The fluid pressure in the second passage 18 will passthrough the ports 221 into the inner portions of the cylinders 220,urging the gripping members or pistons 222 outwardly into firm grippingengagement with the wall of the well casing. Leakage of fiuid aroundeach gripping member is prevented by a suitable side seal :ring 227slidably and sealingly engaging the wall of its cylinder 220.

In the event it is desired to release the well packer with pressure inthe second passage 18 adequate to hold the gripping members 222outwardly against the wall of the well casing C, the second tubularstring H will first be removed from the receptacle to equalize thepressure on the interior and exterior of the gripping members, allowingthe springs 224 to shift them inwardly to retracted position completelywithin the confines of the receptacle or head 17. Thereafter, the wellpacker can be released in the manner described above and removed fromthe well casing.

When latched in its open condition, as illustrated in FIG. 9, thecontrol unit is ineffective to prevent setting of its Well packer uponshifting of the valve sleeve 151 from the position closing the secondpassage port 150. The control unit can be placed initially in thecondition illustrated in FIG. 8, in which the central passage 173through the valve body 165 is closed, the shear screw 180 securing thepiston valve member 170 to the valve body, with the lower piston head174 within its cylindrical seat 173 and closing its central passage. Ifthe valve sleeve 151 were now to be shifted downwardly in the secondpassage 66 to open the port 150, fluid pressure could not passdownwardly through the valve body passage 173 to unseat the check valve192 and enter the cylinders for the purpose of shifting the pistons 111downwardly therewithin and effecting setting of the packer, unless thefluid pressure differential entering the valve body between its upperand lower piston heads 175, 174 is sufficiently high to overcome theshear strength of the screw 180 and shift the piston structure upwardlyto the position illustrated in FIG. 9, thereby opening the centralpassage 173 through the valve body. The strength of the shear screw canbe made quite large, so that a substantial pressure differential must beimposed through the second tubular string H before the piston valve 170can be shifted from its closed to its open position.

If only a single packer were to be run in the well bore, the sleevevalve 151 within the second housing passage could be omitted, ifdesired, and the piston I valve 170 secured in its closed position bymeans of the shear screw 180, as illustrated in FIG. 8. When it isdesired to set the well packer, the second housing passage 66 can beclosed below its open port 150 by any suitable means, as by the ballvalve element 156 engaging a tripping ball seat 229 secured by a shearscrew 230, or the like, to a member 231 threaded on the lower end of thetubular connector 91. The shear screw 230 attaching the seat 229 to itsassociated member 231 requires a much greater fluid pressure to shearthan is required to disrupt the screw 180 holding the piston valvemember 170 in its valve closing position. When the ball 156 engages itsseat 229, suflicient pressure can 17 be built up in the second passage66 for action upon the piston valve 170 to disrupt its associated shearscrew 180 and shift the piston valve to the open position shown in FIG.9, whereupon the pressure in the second passage 66 can be increased todisrupt the shear screw 230 holding the seat 229 to its member 231,blowing the seat and the ball 156 completely out of the member 231,these parts dropping 'harmlessly into the well casing. The hydrostatichead of fluid can now unseat the check valve member 192, 191 and enterthe cylinders 111) to move the pistons 111 downwardly and set the wellpacker.

Packers A, B heretofore described can be run in tandem in the wellcasing C to secure production selectively from a plurality of zones E, Fin the well bore. As disclosed in FIGS. 3a, 3b and 3c, the Well casing Cis disposed in the well bore and passes through the lower, intermediate,and upper producing zones D, E, F, there being the lower, intermediate,and upper casing perforations 10, 11, 12 opposite these zones. The wellpacker J of any suitable type may have previously been installed in thewell casing C between the lower and intermediate casing perforations 10,11. An intermediate well packer B and an upper well packer A areconnected together by means of first and second tubings 29, 250, thefirst tubing 29 being firmly secured to the lower end of the first bodymember 13 of the upper packer A and firmly secured to the upper end ofthe first body 13 of the intermediate packer member B. The second tubing250 is secured to the connector 91 of the upper packer A thatcommunicates with its second passage 66, and the lower end of the tubingstring 250 fits within the second passage 18 of the receptacle 17 of theintermediate packer B. This second tubing 250 includes a telescopicjoint 251 and also a ported structure 252 which can be conditioned toopen its ports 253 to allow fluid from the upper production zone F topass through the upper perforations 12 and into the second passage 66 ofthe upper packer, at which time the second tubing 250 below the ports253 is closed. If desired, the ports 253 can be closed and communicationwith the second passage 66 of the intermediate packer B establishedthrough the tubing 250, so that production from the intermediate zone Ecan flow into the second passage 66 of the intermediate packer B,through the second tubing 25% and the second passage 66 of the upperpacker A into the second tubular string H extending to the top of thewell bore. The lower end of the first body 13 of the intermediate packerB has tubing 254 connected to it extending into the lower packer inappropriate sealing relation therewith, this lower tubing having lowerperforations 255 through which production from the lower zone D can flowinto and through the tubing 254, into the first body 13 of theintermediate packer B, through the first tubing 29 into the first body13 of the upper packer A, continuing on up through the first tubularstring G to the top of the well bore.

The intermediate packer B has the member 231 secured to its lowerconnector 91 containing the tripping ball seat 229 attached thereto bymeans of one or more shear screws 230.

The telescopic joint 251 is of any suitable type. As shown in FIG. 22,it includes an inner mandrel 256 telescopically arranged within an outerhousing 257, there being a seal ring 258mounted on the mandrel slidablyand sealingly engaging the wall of the housing to prevent leakagebetween the interior and exterior of the joint.

The side ported structure 252 can be of any known, suitable type. Asshown in FIG. 21, it includes an outer housing 259, which may be made ofseveral sections, having the ports 253 therethrough. A sleeve valve 260extends initially across these ports to close the same, leakage of fluidthrough the ports being prevented by suitable side seals 261 on thesleeve engaging the wall of the housing 259. The sleeve valve isreleasably retained in port closing position by an inherently,expandible split ring 262 mounted in a sleeve groove 263 and disposedwithin a companion internal groove 264 in the housing, as shown in FIG.22. Through use of a suitable shifting mechanism (not shown), the sleeve26% can be moved upwardly within the housing to align sleeve ports 265with the housing ports 253, the split ring 262 snapping into an upperhousing groove 266 to releasably hold the sleeve in its port openingposition (FIG. 23).

After the sleeve 260 has been shifted to port opening position, thehousing 259 below the ports 253 can be plugged by running a suitableblanking plug 267 through the tubular string H and through the secondpassage of the upper packer A. As disclosed in FIG. 23, this blankingplug includes a mandrel 268 having a central plug 269 below side ports270 in the mandrel. The mandrel carries a suitable side seal 271 adaptedto seal against an inner wall 273 of the housing 259 below its ports253. The mandrel carries suitable lock levers 27 pivoted on hinge pins275 and urged by springs 276 outwardly, the lock levers shifting into acoupling recess 277 formed between the upper end of the housing 259 anda section of the tubing 250 thereabove.

When the blanking plug device 267 shown in FIG. 23 is employed, fluidfrom below the side ported valve device 252 cannot pass upwardly throughthe tubing 251). Instead, it passes through the side ports 253, 265, 270into the tubular mandrel 268 and up through the tubing 250 into thesecond passage 66 of the upper packer A for continued upward movementthrough the second tubular string H to the top of the hole. Removal ofthe blanking plug 267 and shifting of the sleeve valve 260 back to itsport closing position (FIG. 23) will allow production from theintermediate zone E to flow upwardly through the lower packer B andthrough the tubular string 250 into the upper packer A for upwardpassage through the second tubular string H to the top of the hole.Depending upon the position of the valve sleeve 260 and the presence orabsence of the blanking plug 267, production can be secured selectivelyfrom either the intermediate or upper zones E, F for conveyance throughthe second tubular string H to the top of the well bore.

In running the tandem arrangement of packers A, B in the well casing C,they are secured together in appropriate spaced relation through use ofthe intervening first and second tubings 29, 250, with the body member13 of the lower packer B connected to a suitable length of tubing 254 sothat such tubing will be placed in appropriate leak-proof relation tothe lower packer I when .the intermediate packer B is disposed betweenthe intermediate and upper perforations 11, 12 and the upper packer A isdisposed above the upper perforations 12. The control unit of theintermediate packer B preferably will be placed in the conditionillustrated in FIG. 9, in which the central passage 173 through thevalve body is open, as also shown in FIG. 3b, and the control unitthrough the upper packer A will be placed in the closed condition, suchas illustrated in FIG. 8 and FIG. 3a, the shear screw 180 holding thepiston valve member in the closed position. The screw has a much greatershear strength than the screws 152 holding the sleeve valve 151 of thelower packer across the second passage port 150.

The tandem combination of packers A, B is run in a well casing on thefirst tubular string G until the tubing 254 is appropriately related tothe lower packer J, at which time the intermediate and upper packers B,A will also be appropn'ately located in the well casing. The secondtubular string H is now lowered in the well casing alongside the firsttubular string and guided into the second passage 18 of the upper packerA and releasably latched thereto. The tubular strings G, H can beappropriately connected to other devices at the top of the well bore, sothat they need no longer be moved longitudinally, and circulating fluidpumped down the second 19 tubularstring H, which fluid passes throughthe second passage 66 of the upper packer A and the second tubing 250,and through the second passage 66 of the intermediate packer B, thefluid discharging from its lower end. At this time, the side ports 253of the second tubing 250 are closed. Such circulating fluid flowsupwardly around both packers A, B and around the tubular strings G, H tothe top of the Well bore, flushing drilling mud, and the like, ahead ofit out of the well casing.

A tripping ball 156 is now pumped down the second tubular string H,passing into the second tubular body 14 of the upper packer A andengaging the valve sleeve fingers 155 of the upper packer. The buildingup of sufficient pressure will shear the screws 152 holding the sleeve151 to the second body member 14, shifting the sleeve downwardly to aposition opening the second passage port 150, the fingers 155 expandinginto the recess 157 and allowing the ball 156 to continue movingdownwardly through the second tubing 250 and into engagement with thevalve sleeve 151 of the intermediate packer B. If desired, the sleevevalve 151 of the upper packer A can be omitted. The upper packer Acannot set at this time since its piston valve 170 is in the closedposition, the shear screw 180 holding it in such position remainingintact. When the tripping ball engages the fingers 155 of the valvesleeve 151 of the intermediate packer, pressure can be built up in thesecond tubular string H and in the second passages 66 and interveningtubing 250 sufiicient to disrupt the shear screws 152 holding the sleeveto the second body member 14, allowing the sleeve to shift downwardlybelow the second passage ports 150, its fingers expanding outwardly intothe recess 157 and allowing the ball to come to rest upon the lowervalve seat 229. The control unit of the intermediate packer B was placedpreviously in the open condition illustrated in FIG. 9, so that thehydrostatic head of fluid in the well bore can now pass through thecontrol unit, unseating the check valve members 192, 191 and enteringthe cylinders 110 in order to elfect expansion of the slips 56 andpacking 42 of the intermediate packer B against the wall of the wellcasing C.

The body member 13 of the intermediate packer does not move downwardlyduring its setting in the well casing, nor is the downward movement ofthe receptacle 17 of the intermediate packer transmitted to the upperpacker A through the second tubing 250, in view of the telescopic joint251 incorporated therein. I Fluid pressure can now be built up in thesecond tubular string H and in the second passages 66 of the packers andthe second tubing 250 in an amount to act upon the upper piston head 174of the upper packer control unit 126, to disrupt its shear screw 180 andshift the piston valve member 170 upwardly to the position illustratedin FIG. 9, opening the central passage 173 through this control unit,and allowing the hydrostatic head of fluid or fluid pressure developedin the second tubular string H to unseat the check valve 192 and pass tothe cylinders 110 of the upper packer A, thereby effecting expansion ofits slips 56 and packing assembly 42 into engagement with the wall ofthe well casing C. The fluid pressure in the second tubular string H cannow be further increased to a value disrupting the lower shear screw230, to eject the trip ball 156 and the tripping ball seat 229 from themember 231 into the well casing C.

Well production from the lower zone D can now pass through the tubing254 and through the first members 13, 29, 13 into the first tubularstring G, to be conducted thereby to the top of the well bore. Wellproduction from the intermediate zone B can now pass into the secondpassage 66 of the intermediate packer B, through the second tubing 250and through the second passage 66 of the upper packer A into the secondtubular string H to be conducted thereby to the top of the well bore. Inthe event it is desired to conduct production from the upper zone F tothe top of the well bore, the sleeve valve 260 is shifted to a portopening position by suitable wire line tools (not shown), after whichthe passage through the second tubing 250 below the ports 253 is closedby running and latching the blanking plug 267 in position to preventproduction from the intermediate zone E from passing upwardly throughthe packer B, second tubing 250 and upper packer A into the secondtubular string H. With this condition of the apparatus, well productionfrom the lower zone D will continue to pass upwardly into the firsttubular string G, and production from the upper zone F will pass throughthe side ports 253 into the second tubing 250 and upwardly through thesecond passage 66 of the upper packer A into the second tubular string Hto be conducted thereby to the top of the well bore.

If desired, the sleeve valve 260 can be reshifted to close itsassociated ports 253 and open the passage of the tubing 250 therebelow.so as to again secure production from the intermediate zone B, in lieuof from the upper zone F.

*If the hydraulic anchor devices 220 to 227 are used in the packers, thegripping members 222 will expand outwardly and will prevent pressurebelow the packers from shifting them upwardly in the well casing.

In the event it is desired to release the upper and intermediate packersA, B from the well casing, the second tubular string H can be pulled outof the upper packer receptacle 17, which will equalize the pressureacross the gripping members 222, causing their springs 224 to retractthem within the receptacle cylinders 220. The turning of the firsttubular string 13 will disrupt the break plugs 134 in both the upper andintermediate packers A, B, allowing the pressures in the cylinders 110on opposite sides of their pistons 111 to be equalized. The exertion ofsuflicient torque will also act through the mechanical advantage devices83, to disrupt the shear rings 86 securing the first body members 13 totheir hydraulic housings 67, allowing the first tubular body member ineach packer to be elevated, producing elevation of the upper portions ofthe packers A, B with respect to their lower portions, and allowingretraction of the packing elements 46 and slips 56, permittingwithdrawal of the well packers A, B from the well casing C, as well asthe intervening and lower tubings 29, 250, 254.

Each packer A, B will function individually in the same manner as itwould function if disposed separately in the well bore with respect tothe action of the check valve 125 in preventing bleeding of pressurefrom the cylinders in the event the hydrostatic head of fluid in thewell bore drops below the minimum setting pressure required to maintaina packer anchored in packedotf condition in the well casing. Moreover,material diminution of the trapped pressure in the cylinders below theminimum setting pressure, as a result of rubber packlng extrusion, forexample, cannot result since the energy stored in the accumulatordevices 114422 will maintain the required pressure in the cylinders 110.

I claim:

1. In apparatus adapted to be set in a well bore: body means; normallyretracted means on said body means adapted to be expanded outwardly intoengagement with the wall of the well bore; fluid operated meansresponsive to the hydrostatic head of fluid in the well bore forexpanding said normally retracted means outwardly; means for preventingflow of fluid from said fluid operated means upon reduction of thehydrostatic head of fluid in the well bore below the pressure in saidfluid operated means; and accumulator means for maintaining the pressurein the entrapped fluid within said fluid operated means.

2. In apparatus adapted to be set in a well bore: body means; normallyretracted means on said body means adapted to be expanded outwardly intoengagement with the wall of the well bore; fluid operated means forexpanding said normally retracted means outwardly and having a highpressure and a low pressure side; means for conducting fluid underpressure to the high pressure side of said fluid operated means toactuate said fluid I and low pressure sides of said fluid operated meansto permit retraction of said normally retracted means from its outwardlyexpanded position.

3. In apparatus adapted to be in a well bore: body means; normallyretracted means on said body means adapted to be expanded outwardly intoengagement with the wall of the well bore; fluid operated means responsive to the hydrostatic head of fluid in the well bore for expandingsaid normally retracted means outwardly; means for preventing flow offluid from said fluid operated means upon reduction of the hydrostatichead of fluid in the well bore below the pressure in said fluid operatedmeans; accumulator means for maintaining the pressure in the entrappedfluid within said fluid operated means; and means for substantiallyequalizing the hydrostatic head of fluid acting on said fluid operatedmeans to permit retraction of said normally retracted means from itsoutwardly expanded position.

4. In apparatus adapted to be set in a well bore: body means; normallyretracted means on said body means adapted to be expanded outwardly intoengagement with the wall of the well bore; fluid operated means forexpanding said normally retracted means outward and having a highpressure and a low pressure side; means for connecting fluid underpressure to the high pressure side of said fluid operated means toactuate said fluid operated means; means for preventing flow of fluidfrom said high pressure side; accumulator means for maintaining thepressure in the entrapped fluid on the high pressure side of said fluidoperated means; and means operable by said body means for substantiallyequalizing the fluid pressure on said high and low pressure sides ofsaid fluid operated means to permit retraction of said normallyretracted means from its outwardly expanded position.

5. In apparatus adapted to be set in a well bore: body means; normallyretracted means on said body means adapted to be expanded outwardly intoengagement with the wall of the well bore; fluid operated means forexpanding said normally retracted means outwardly and having a highpressure and a low pressure side; means for conducting fluid underpressure to the high pressure side of said fluid operated means toactuate said fluid operated means; means for preventing flow of fluidfrom said high pressure side; accumulator means for maintaining thepressure in the entrapped fluid on the high pressure side of said fluidoperated means; initially closed means adapted to provide simultaneouscommunication between the fluid in the well bore and said high and lowpressure sides of said fluid operated means to permit retraction of saidnormally retracted means from its outwardly expanded position; and meansfor opening said initially closed means.

6. In apparatus adapted to be set in a well bore: body means; normallyretracted means on said body means adapted to be expanded outwardly intoengagement with the wall of the well bore; fluid operated means forexpanding said normally retracted means outwardly; means for conductingfluid under pressure to said fluid operated means to actuate the same;means for preventing flow of fluid from said fluid operated means;accumulator means for maintaining the pressure in the fluid within saidfluid operated means; said accumulator means comprising a movable headhaving a high pressure side subject to the same fluid pressure as saidfluid operated means; and yieldable means in which the full energy ofsaid fluid pressure is storable acting on'the low pressure side of saidhead to resist movement of said head by said fluid pressure.

7. In apparatus adapted to beset in a well bore: body means; normallyretracted means on said body means adapted to be expanded outwardly intoengagement with the wall of the well bore; fluid operated means forexpanding said normally retracted means outwardly; means for conductingfluid under pressure to said fluid operated means to actuate the same;means for preventing flow of fluid from said fluid operated means;accumulator means for maintaining the pressure in the fluid within saidfluid operated means; said accumulator means comprising a movable headhaving a high pressure side subject to the same fluid pressure as saidfluid operated means; and spring means in which the full energy of saidfluid pressure is storable acting on the low pressure side of said head.to resist movement of said head by said fluid pressure.

8. In apparatus adapted to be set in a well bore: body means; normallyretracted means on said body means adapted to be expanded outwardly intoengagement with the wall of the well bore; fluid operated means forexpanding said normally retracted means outwardly; means for conductingfluid under pressure to said fluid operated means to actuate the same;means for preventing flow of fluid from said fluid operated means;accumulator means for maintaining the pressure in the fluid within saidfluid operated means; said accumulator means comprising a movable headsubject to the same fluid pressure as said fluid operated means; and aplurality of coengaging conical spring washers engaging said head toresist movement of said head by said fluid pressure.

9. In apparatus adapted to be set in a well bore: body means; normallyretracted means on said body means adapted to be expanded outwardly intoengagement with the wall of the well bore; hydraulically operable meansfor expanding said normally retracted means outwardly comprisinghydraulic cylinder means, hydraulic piston means in said cylinder means;means for conducting fluid under pressure to said cylinder means torelatively move said cylinder means and piston means and expand saidnormally retracted means outwardly; means for preventing flow of fluidfrom said cylinder means; accumulator means for maintaining the pressurein the fluid within said cylinder means, comprising a movable headhaving'a high pressure side subject to the same fluid pressure as saidcylinder means; and yieldable means in which the full energy of saidfluid pressure is storable acting on the low pressure side of said headto resist movement of said head by said fluid pressure.

iii. In apparatus adapted to be set in a well bore: body means; normallyretract-ed means on said body means adapted to be expanded outwardlyinto engagement with the wall of the well bore; hydraulically operablemeans for expanding said normally retracted means outwardly com-prisinghydraulic cylinder means, hydraulic piston means in said cylinder means;means for conducting fluid under pressure to said cylinder means torelatively move said cylinder means and piston means to expand saidnormally retracted means outwardly; means for preventing flow of fluidfrom said cylinder means; said cylinder means including a movable headsubject to the pressure of fluid in said cylinder means; and yieldablemeans acting on said head to resist movement of said head by fluidpressure in said cylinder means and tending to maintain the fluid insaid cylinder means under pressure.

11. In apparatus adapted to be set in a well bore: body means; normallyretracted means on said body mean-s adapted to be expanded outwardlyinto engagement with the wall of the well bore; hydraulically operablemeans for expanding said normally retracted means outwardly comprisinghydraulic cylinder means, hydraulic piston means in said cylinder means;means for conducting the hydrostatic head of fluid in the well bore tosaid cylinder means to relatively move said cylinder means and pistonmeans to expand said normally retracted means outwardly; means forpreventing flow of fluid from said cylinder means upon reduction of thehydrostatic'head of fluid in the well bore below the pressure in saidcylinder

1. IN APPARATUS ADAPTED TO BE SET IN A WELL BORE: BODY MEANS; NORMALLYRETRACTED MEANS ON SAID BODY MEANS ADAPTED TO BE EXPANDED OUTWARDLY INTOENGAGEMENT WITH THE WALL OF THE WELL BORE; FLUID OPERATED MEANSRESPONSIVE TO THE HYDROSTATIC HEAD OF FLUID IN THE WELL BORE FOREXPANDING SAID NORMALLY RETRACTED MEANS OUTWARDLY; MEANS FOR PREVENTINGFLOW OF FLUID FROM SAID FLUID OPERATED MEANS UPON REDUCTION OF THEHYDROSTATIC HEAD OF FLUID IN THE WELL BORE BELOW THE PRESSURE IN SAIDFLUID OPERATED MEANS; AND ACCUMULATOR MEANS FOR MAINTAINING THE PRESSUREIN THE ENTRAPPED FLUID WITHIN SAID FLUID OPERATED MEANS.